Direct measurement of petroleum API gravity or petroleum phase can be extremely difficult to obtain from rock samples taken from a subsurface well where fluid tests (e.g., drill stem tests (DST), modular dynamic tests (MDT), repeat formation tests (RFT), etc.) are not economically feasible, or not available. However, fluid property information (e.g., API gravity, fluid phase) is often important for evaluating and planning well or field development and further exploration. Rock samples (e.g., sidewall cores, core, or cuttings) are often readily available but typically do not contain enough petroleum to perform actual measurements of relevant properties.
There are several previously known methods for analyzing alkanes and pseudo-components from well tests or production petroleum fluids (oils or condensates) (Katz and Firoozabadi, 1978; Pedersen and Christensen, 2007). Proper measurement of fluid properties and recognition of fluid phase can be highly dependent on whether sufficient volume is available (˜5-100 milliliters). Unfortunately, these methods do not work well for smaller sample volumes. Previous methods have used biomarker analysis, gas chromatography/mass spectrometry (GCMS), and/or gas chromatography/tandem mass spectrometry (GCMSMS) to constrain oil quality by one of several approaches. For example, biomarker ratios can either be directly correlated to an oil quality parameter (i.e., API gravity) or combined by a statistical approach to determine oil quality (Hughes and Holba, 1988; Smalley et al., 1996; Michael, 2003; Huizinga et al., 2007). Biomarker parameters may also be used to constrain oil type (e.g., low sulfur-low asphaltene, medium sulfur-medium asphaltene, or high sulfur-high asphaltene contents) and/or thermal maturity (maximum temperature experienced). Once the oil type and maturity are established, Pressure-Viscosity-Temperature (PVT) reports for similar oils may be used to estimate probable oil properties. Other methods include pyrolysis of rock samples by Rock-Eval pyrolysis (Holba et al., 2004; Dow et al., 2001; Dow and Talukdar, 1991; Baskin and Jones, 1993) or pyrolytic oil-productivity index (POPI) method (Jones and Tobey, 1999; Jones et al., 2004; Jones and Halpern, 2007) can provide proportion of light fluid versus pyrolyzed product from heavy oil components, which in turn can be correlated with bulk fluid properties. Pyrolysis methods can work best for heavy oils (API<25). Oil quality predictions have been attempted using well logging techniques such as NMR or CMR logging (Zhang et. al., 1998).
Some previous methods for predicting oil quality have certain disadvantages. As alluded earlier, quality of measurements in some previous methods can be significantly limited by amount of sample available. In some cases, rock samples (sidewall cores, cores, or cuttings) may only contain trace amounts of petroleum (microgram to milligram amounts). In other situations, oil samples may be available but can be hampered by contamination issues with drilling fluids. Biomarker methods usually require extensive analysis and interpretation and are relatively more expensive and time consuming than gas chromatography. Moreover, biomarker methods work well for black oils but often do not work well for light oil or condensate contributions to an accumulation which contain little or no biomarkers.